Novel corrosion inhibition package

ABSTRACT

A corrosion inhibition package for use with an aqueous acid composition, said package comprising: a terpene; a cinnamaldehyde or a derivative thereof; at least one amphoteric surfactant; and a solvent. Also disclosed are compositions comprising said corrosion inhibitor package. Preferably, the corrosion inhibition package meets the environmental requirements for classification as yellow according to the Norwegian North Sea offshore drilling regulatory requirements.

FIELD OF THE INVENTION

This invention relates to corrosion inhibition packages for use withacidic compositions, more specifically to corrosion inhibition packageswhich provide an enhanced environmentally-friendly characteristic whilestill providing industry-leading corrosion protection.

BACKGROUND OF THE INVENTION

In the oil & gas industry, stimulation with an acid is performed on awell to increase or restore production. In some instances, a wellinitially exhibits low permeability, and stimulation is employed tocommence production from the reservoir. In other instances, stimulationor remediation is used to further encourage permeability and flow froman already existing well that has become under-productive.

Acidizing is a type of stimulation treatment which is performed above orbelow the reservoir fracture pressure in an effort to restore orincrease the natural permeability of the reservoir rock. Acidizing isachieved by pumping acid into the well to dissolve typically limestone,dolomite and calcite cement between the sediment grains of the reservoirrocks or to treat acid soluble scale accumulation.

There are three major types of acid applications: matrix acidizing,fracture acidizing, and breakdown acidizing (pumped prior to afracturing pad or cement operation in order to assist with formationbreakdown (reduce fracture pressures, increased feed rates), as well asclean up left over cement in the well bore or perforations. A matrixacid treatment is performed when acid is pumped into the well and intothe pores of the reservoir formation below the fracture pressure. Inthis form of acidization, the acids dissolve the sediments formationand/or mud solids that are inhibiting the permeability of the rock,enlarging the natural pores of the reservoir while creating wormholesand stimulating flow of hydrocarbons to the wellbore. While matrixacidizing is when pressures are maintained below the fracture gradient,fracture acidizing involves pumping highly pressurized acid into thewell above the formation fracture gradient, physically fracturing thereservoir rock allowing the acid to etch the permeability inhibitivesediments. This type of acid treatment forms channels or fractures andetches through which the hydrocarbons can flow. In some instances, aproppant is introduced into the fluid which assists in propping open thefractures, further enhancing the flow of hydrocarbons into the wellbore.

There are many different mineral and organic acids used to perform anacid treatment on wells. The most common type of acid employed on wellsto stimulate production is hydrochloric acid (HCl), which is useful instimulating carbonate reservoirs.

Some of the major challenges faced in the oil & gas offshore industryfrom using hydrochloric acid include the following: extremely highlevels of corrosion (which is countered by the addition of ‘filming’type corrosion inhibitors that are typically themselves toxic andharmful to humans, the environment and equipment and thus affect theclassification rating or use in many offshore jurisdictions (such as theNorth Sea). Reactions between acids and various types of metals can varygreatly but softer metals, such as aluminum and magnesium, are verysusceptible to major effects causing immediate damage. Hydrochloric acidproduces Hydrogen chloride gas which is toxic (potentially fatal) andcorrosive to skin, eyes and metals. At levels above 50 ppm (parts permillion) it can be Immediately Dangerous to Life and Health (IDHL). Atlevels from 1300-2000 ppm death can occur in 2-3 minutes.

The inherent negative effects (organic sterility, poisoning of wildlife,personnel exposure, high corrosion, hazardous fumes etc.) of HCl and thehighly toxic and dangerous corrosion inhibitors added to reduce thiscorrosion can, in the event of an unintended or accidental release, onsurface or down hole into water aquifers or other sources of water aredevastating which can cause significant pH reduction of such and cansubstantially increase the toxicity and could potentially cause a massculling of aquatic species and potential poisoning of humans orlivestock and wildlife exposed to/or drinking the water. An unintendedrelease at surface can also cause a hydrogen chloride gas plume to bereleased, potentially endangering human and animal health. This is acommon event at large storage sites when tanks split or leak. Typicallyif near the public, large areas need to be evacuated post event and acomprehensive, expensive to implement, emergency evacuation plan need tobe in place prior to approval of such storage areas. Because of itsacidic nature, hydrogen chloride gas is also corrosive, particularly inthe presence of moisture. A method to overcome gas fuming is byutilizing novel synthetic or modified acids which have an ability togreatly minimize this drawback all the while maintaining the efficiencyof the acid downhole.

The inability for acids, and blends of such, to biodegrade naturallywithout neutralizing the soil results in expensive cleanup-reclamationcosts for the operator should an unintended release occur. Moreover, thetoxic fumes produced by mineral & some organic acids are harmful tohumans/animals and are highly corrosive and/or produce potentiallyexplosive vapours. Transportation and storage requirements for acids arerestrictive and taxing in such that you must haul the products in acidapproved tankers or intermediate bulk containers (IBC) that are rated tohandle such corrosive products. As well, the dangers surroundingexposure by personnel handling the blending of such corrosive/dangerousproducts limits their use/implementation. Some if not most of theseproblems have been greatly minimized through the use of synthetic acidsas mentioned above.

Another concern is the potential for human or environmental exposureincidents on locations due to high corrosion levels of acids causingstorage container failures and/or deployment equipment failures i.e.coiled tubing or fracturing iron failures caused by high corrosion rates(pitting, cracks, pinholes and major failures). Other concerns include:downhole equipment failures from corrosion causing the operator to haveto execute a work-over and replace down hole pumps, tubing, cables,packers etc.; inconsistent strength or quality level of mineral &organic acids; potential supply issues based on industrial outputlevels; high levels of corrosion on surface pumping equipment resultingin expensive repair and maintenance levels for operators and servicecompanies; the requirement of specialized equipment that is purposebuilt to pump acids greatly increasing the capital expenditures ofoperators and service companies; and the inability to source a finishedproduct locally or very near its end use; transportation and onsitestorage difficulties.

Extremely high corrosion and reaction rates with temperature increasecauses conventional acids to “spend/react or become neutral” prior toachieving its desired effect such as deeply penetrating an oil or gasformation to increase the wormhole or etched “pathway” effectively toallow the petroleum product to flow freely to the wellbore. As anexample, hydrochloric acid can be utilized in an attempt to free stuckdrill pipe in some situations. Prior to getting to the required depth todissolve the formation that has caused the pipe/tubing to become stuckmany acids spend or neutralize due to increased bottom hole temperaturesand greatly increased reaction rate, so it is advantageous to have analternative that spends or reacts more methodically allowing the sloughto be treated with a solution that is still active, allowing thepipe/tubing to be pulled free.

When used to treat scaling issues on surface due to water contamination,conventional acids are exposed to human and mechanical devices as wellas expensive pumping equipment causing increased risk for the operatorand corrosion effects that damage equipment and create hazardous fumes.When mixed with bases or higher pH fluids or even water, acids willcreate a large amount of thermal energy (exothermic reaction) causingpotential safety concerns and equipment damage, acids typically need tobe blended with fresh water (due to their intolerance of highly salinewater, causing potential precipitation of minerals) to the desiredconcentration requiring companies to pre-blend off-site as opposed toblending on-site with field/produced water thereby increasing costsassociated with transportation.

Conventional mineral acids used in a pH control situation can causerapid degradation of certain polymers/additives requiring increasedloadings or chemicals to be added to counter these negative effects.Many offshore areas of operations have very strict regulatory rulesregarding the transportation/handling and deployment of acids causingincreased liability and costs for the operator. When using an acid topickle tubing or pipe, very careful attention must be paid to theprocess due to high levels of corrosion, as temperatures increase, thetypical additives used to control corrosion levels in acid systems beginto degrade very quickly (due to the inhibitors “plating out” on thesteel) causing the acids to become very corrosive and resulting indamage to downhole equipment/tubulars.

Acids perform many actions in the oil & gas industry and are considerednecessary to achieve the desired production of various petroleum wells,maintain their respective systems and aid in certain drillingoperational functions (i.e. freeing stuck pipe, filter cake treatments).The associated dangers that come with using mineral acids are expansiveand tasking to mitigate through controls whether they are chemically ormechanically engineered. The required addition of corrosion inhibitorsystems that are toxic, incompatible with anionic additives, containhazardous materials such as quaternary amines, which are thought to bethe chemical group responsible for anaphylactic reactions along withother negative human effects. Any corrosion inhibitor that is effectivein HCl or modified and synthetic acids is advantageous. Eliminating oreven simply reducing the negative effects of acids while maintainingtheir usefulness is a struggle for the industry due to the limitedavailability of friendlier, effect corrosion inhibitor systems. As thepublic demand for the use of cleaner/safer/greener products increases,companies are looking for alternatives that perform the requiredfunction without all or most of the drawbacks associated with the use ofconventional mineral acids. Some of the problems raised above have beengreatly mitigated through the implementation and use of novel syntheticand modified acids and corrosion inhibitors. However, even some of thosesynthetic and modified acid compositions comprise certain chemicalswhich prohibit their use in certain environments, namely the corrosioninhibitor components.

Offshore, and now many onshore (European areas as an example) oil andgas operations are highly regulated or becoming highly regulated due tothe environmental and human exposure concerns which arise from theiroperations and the potential for spills and water table contamination.The complexity of drilling and completing offshore and onshore wells iscompounded by both safety issues for workers on such work sites andproduction platforms, facilities as well as environmental concerns. Inmost all cases and jurisdictions approved offshore corrosion inhibitorand/or acid systems will meet or exceed the required toxicity andbiodegradation parameters for onshore use, even in highly restrictedareas.

Many countries bordering the waters where offshore drilling andproduction is routinely carried out have implemented a number ofregulations aimed at minimizing the environmental impact of thispractice. These regulations include the ban on certain types ofchemicals which may be harmful to marine life and the environment orhave overall toxicity levels that could be harmful to humans, animals orthe environment in general. In order to overcome these very restrictiveregulations, many oil companies employ very costly containment programsfor the handling of certain chemicals such as acids with commoncorrosion inhibitors which have a wide array of uses in the industry ofoil and gas exploration and production along within other industries.

Norwegian offshore drilling regulations are amongst the most stringenton the planet. The regulatory authorities routinely carry out monitoringof the water column in each of the 11 offshore regions of Norwegianwaters.

This monitoring involves the measurement and tracking of pollutants orbiological effects of pollutants, using caged or wild-caught organisms.This allows the regulatory authorities to assess the impact of offshoredrilling on the marine fauna. In concert with these intense regulatorymonitoring activities, the approval of offshore chemicals is anotheraspect that is intensely controlled. Currently there are only twocompanies in the world that have a fully classified “Yellow” corrosioninhibitor system by the Norwegian authorities, NEMS.

In addition to the water column monitoring, the regulatory body takessediment samples from the seabed to assess the pollution which does notenter fishes and other organisms. These physical and chemical sedimenttesting seek to quantify: the total organic matter (TOM); grain sizedistribution; hydrocarbons and synthetic drilling fluids; metals; andradioactivity.

The chemicals are classified according three main criteria: persistence(lack of biodegradation, liability to bioaccumulate and toxicity.

Many of the issues related with offshore oil and gas exploration andproduction stem from the fact that the conditions under which this iscarried out are substantially different than those encountered in thesame types of operations carried out onshore.

Acidic compositions and corrosion inhibitors conventionally used invarious oil and gas operations can reach temperatures of up to 130° C.and above. At these temperatures, their reactivity is exponentiallyincreased and, as such, their effectiveness or even their ability to beutilized is greatly decreased. Corrosion is the major concern at hightemperatures and is difficult and expensive to control with additional,currently available chemistry.

Modified and synthetic acids developed and currently patented are aimedat, but not limited too, increasing personnel safety, reducing corrosioneffects, reducing environmental damage, retarding the reaction anddiffusion rate, increasing worm-holing efficiency (reducing competingwormholes) and reducing the toxicity profile of HCl. Additionally, thereis the risk of wellbore and/or formation damage due to uncontrolledsolubilized mineral precipitation due to an increase in the pH causedmainly by the formation of ammonia during the decomposition phase fromurea-hydrochloride based systems. The advent of more advanced syntheticor modified acids is intended on providing usage at higher temperatureswhile still maintain the performance, safety and environmentaladvantages and benefits of a urea-HCl modified or synthetic acid system,but ultimately at these higher temperatures it is most often desirableto utilize additional or purpose developed corrosion inhibition packagesand/or components to control corrosion of exposed steel and minimizenegative effects on elastomers and the formation itself. In thatrespect, even short exposure times at high temperature are more damagingto steel than longer exposure times at lower temperatures. In keepingwith the industrial shift, there is also a strong desire to developcorrosion packages which are more “environmentally friendly and moreeffective” than conventional or currently available systems.

EP patent application 1 724 375 A2 discloses an aqueous organic acidcomposition containing a terpene as corrosion inhibitor intensifier saidto be especially suitable for use in acidizing subterranean formationsand wellbores. The composition is said to substantially reduce thecorrosive effects of the acidic solution on metals in contact with theacidic solution. Suitable terpenes are said to include carotene,limonene, pinene, farnesene, camphor, cymene and menthol.

U.S. Pat. No. 8,765,021 teaches an aqueous treatment composition forinhibiting corrosion and acid attack on metallic surfaces that comprisesa thiourea organic derivative, a polyalkoxylated terpene nonionicsurfactant and an acid. It is stated that the invention also relates toa process for cleaning industrial metallic equipment, in particular heatexchangers in which a heat transfer fluid, generally based on air or onwater, flows, with a view to cleaning them and removing scale and othersoiling.

US patent application no. 2003/0166472 discloses a well treatmentmicroemulsion that is formed by combining a solvent-surfactant blendwith a carrier fluid. In preferred embodiments, the solvent-surfactantblend includes a surfactant and a solvent selected from the groupconsisting of terpenes and alkyl or aryl esters of short chain alcohols.The description states that the disclosed well treatment microemulsioncan be used in well remediation, stimulation and hydrogen sulfidemitigation operations.

U.S. Pat. No. 8,323,417 teaches a method of treatment for inhibitingsulfur-based corrosion or scaling or for removing scaling from a surfaceincluding inhibiting corrosion caused by sulfur-containing materials,reducing corrosion caused by sulfur-containing materials, inhibitingscaling caused by sulfur-containing materials in gas, liquid or solidphase or any combination of multiple phases of materials, reducingscaling caused by sulfur-containing materials, and removing scalingcaused by sulfur-containing materials. The method involves contactingsulfur-containing materials with a composition containing a turpentineliquid, wherein said turpentine liquid comprises α-terpineol,β-terpineol, β-pinene, and p-cymene.

US patent application no. 2006/0264335 A1 discloses an aqueous organicacid composition containing a terpene as corrosion inhibitor intensifieris especially suitable for use in acidizing subterranean formations andwellbores. It is stated that the composition substantially reduces thecorrosive effects of the acidic solution on metals in contact with theacidic solution. Suitable terpenes are said to include carotene,limonene, pinene, farnesene, camphor, cymene and menthol.

U.S. Pat. No. 9,074,289 B2 discloses a method of inhibiting corrosion ofa surface in contact with a corrosive environment encountered in oil andgas operations. The method includes contacting the surface with acomposition comprising a quaternary nitrogen-containing corrosioninhibitor. The patent teaches the use of such inhibitor at levelsranging from 0.1 to 8%.

Despite the various known corrosion inhibition packages and components,there is still a need for corrosion inhibition packages for use withHCl, modified and synthetic acid compositions in the oil industry whichcan be used over a range of applications, that are formulated to beuseful for synthetic and modified acid systems and still be effectivewith conventional acids such as HCl and can be used at high temperatures(i.e. ˜130° C.) without having its components degrade, phase out ofsolution while having a superior safety and environmental profile overknown packages and components during use across a broad range oftemperatures. Moreover, it is desirable to have corrosion inhibitionpackages that do not undermine the advantages of environmentally andpersonnel-friendly acid compositions such as various synthetic andmodified acid compositions which have far fewer deleterious effects thantypical conventional mineral and some organic acids.

Certain corrosion inhibitors components such as propargyl alcohol areundesirable in offshore and on-shore application such as in the NorthSea as it is classified red in Norwegian waters and moreover has a poorperformance on the popular Cr-13 alloys since it tends to allow thepitting of the surface. Surfactants are desirable when used incombination with corrosion inhibitors but they also carry their own setof issues, as they have in general a high acute fish toxicity and lowerbiodegradability (less than 60% in seawater). In light of thosedrawbacks, short chain non-ionic surfactants are typically preferred,because they typically exhibit better acute fish toxicity. However, adisadvantage of short chain non-ionic surfactants is that they usuallyhave lower dispersion ability. Therefore, it is much more difficult and,in some cases, not possible to disperse a relatively hydrophobiccorrosion inhibition component (such as citral or also cinnamaldehyde orother terpenes) with a nonionic surfactant.

In light of the prior art, the inventors have formulated corrosioninhibiting compositions capable of overcoming at least one of thedrawbacks of known acidic compositions. It was surprisingly discoveredthat the corrosion inhibition packages according to the presentinvention exhibit stability when combined with acidic compositions underexposure to elevated temperature (up to and above 130° C.) as well asbeing compatible with anionic additives. This consequently makes themuseful in various industries using acids at these temperaturesincluding, but not limited to, the oil and gas industry.

SUMMARY OF THE INVENTION

The inventors have unexpectedly discovered that a specific surfactantclass that is rated yellow for North Sea applications can also providevery good dissolution of corrosion inhibitors with loading ranges thatmake it economically feasible to use. This class of surfactant, amidobetaines, allow the production of a stable dispersion of a terpenecomponent in acid without phase separation, while providing a yellowrating in Norwegian waters. According to a first aspect of the presentinvention, there is provided a corrosion inhibition package for use withan aqueous acid composition, said package comprising:

-   -   a terpene;    -   a cinnamaldehyde or a derivative thereof;    -   at least one amphoteric surfactant; and    -   a solvent.

Preferably, the terpene is selected from the group consisting of:citral; ionone; ocimene; carvone; and cymene. A preferred terpene iscitral.

Preferably, the at least one amphoteric surfactant is selected from thegroup consisting of: a sultaine surfactant; a betaine surfactant; andcombinations thereof. More preferably, the sultaine surfactant andbetaine surfactant are selected from the group consisting of: an amidobetaine surfactant; an amido sultaine surfactant; and combinationsthereof. Yet even more preferably, the amido betaine surfactant and isselected from the group consisting of: an amido betaine comprising ahydrophobic tail from C8 to C16. Most preferably, the amido betainecomprising a hydrophobic tail from C8 to C16 is cocamidobetaine.

Preferably, the corrosion inhibition package according to the presentinvention is comprised of components giving it an environmentalclassification in Norwegian waters of at least “Yellow”.

Preferably also, the corrosion inhibition package further comprises ananionic surfactant. Preferably, the anionic surfactant is a carboxylicsurfactant. More preferably, the carboxylic surfactant is a dicarboxylicsurfactant. Even more preferably, the dicarboxylic surfactant comprisesa hydrophobic tail ranging from C8 to C16. Most preferably, thedicarboxylic surfactant is sodium lauriminodipropionate

Preferably, the surfactant is selected from the group consisting of:cocamidopropyl betaine; ß-Alanine, N-(2-carboxyethyl)-N-dodecyl-, sodiumsalt (1:1); and a combination thereof.

Preferably, the solvent is selected from the group consisting of:methanol; ethanol; isopropanol; ethylene glycol; and 2-butoxyethanol;and combinations thereof. A preferred solvent is methanol. According toa preferred embodiment of the present invention, short chain ethoxylatesare used as solvent. Preferably, the short chain ethoxylate is NOVEL®6-3 Ethoxylate. This is a biodegradable, nonionic surfactant derivedfrom linear primary ALFOL® 6 Alcohol. It is essentially 100% active andhas the following structural formula: CH3(CH2)4CH2(OCH2CH2)3OH. It is aclear, colorless liquid that is sparingly soluble in water but solublein hydrocarbons.

Preferably, the terpene is present in an amount ranging from 2% to 25%by weight of the total weight of the corrosion inhibition package.Preferably also, the cinnamaldehyde or derivative thereof is present inamount ranging from 2 to 25% by volume of the volume of the corrosioninhibitor. Preferably also, the at least one surfactant is present in anamount ranging from 2% to 20% by volume of the total volume of thecorrosion inhibition package. Preferably also, the solvent is present inan amount ranging from 25% to 80%, more preferably from 25% to 75% byvolume of the total weight of the corrosion inhibition package.

According to another aspect of the present invention, there is providedan acidic composition comprising:

-   -   an acid;    -   a corrosion package comprising:        -   a terpene;        -   a cinnamaldehyde or a derivative thereof;        -   at least one surfactant; and        -   a solvent;

wherein the volume % of the corrosion package in the acidic compositionranges from 0.1 to 7.5%. Preferably, the acidic composition furthercomprises a metal iodide or iodate.

Preferably the weight/volume % of the metal iodide or iodate in theacidic composition ranges from 0.1 to 1.5%. More preferably, the wt/vol.% of the metal iodide or iodate in the acidic composition ranges from0.25 to 1.25%. Even more preferably, the wt/vol. % of the metal iodideor iodate in the acidic composition is approximately 1%. Preferably, themetal iodide or iodate selected from the group consisting of: cuprousiodide; potassium iodide; sodium iodide; lithium iodide and combinationsthereof. More preferably, the metal iodide is potassium iodide.

According to one aspect of the present invention, there is provided anacidic composition comprising a corrosion inhibition package accordingto the invention and an acid selected from the group consisting of:mineral acids; organic acids, synthetic acids; and combinations thereof.More preferably, the acid is selected from the group consisting of: HCl;Lysine-HCl; Urea-HCl; hydrofluoric acid; sulfuric acid; phosphoric acid;phosphoric acid-urea; p-toluene sulfonic acid; methanesulfonic acid; andmethanesulfonic acid-urea. Even more preferably, the acid is HCl,Urea-HCl, lysine-HCl or monoethanolamine (MEA)-HCl. Certain combinationsof acids can also mixed with a corrosion inhibitor package according toa preferred embodiment of the present invention.

According to an aspect of the present invention, there is provided anaqueous synthetic or modified acid composition for use in onshore oiland gas operations, said composition comprising: lysine and hydrochloricacid in a molar ratio of not less than 1:12; a surfactant; a corrosioninhibitor; and an intensifier. Preferably, not less than 1:8, morepreferably 1:5. According to another preferred embodiment, the ratio isof not less than 1:3.

According to a preferred embodiment of the present invention, there isprovided an aqueous synthetic or modified acid composition for use inoffshore and onshore oil and gas and industrial operations, saidcomposition comprising: urea and hydrochloric acid in a molar ratio ofnot less than 0.1:1; a corrosion inhibitor; and an intensifier. Morepreferably, the ratio is not less than 0.3:1; even more preferably, theratio is not less that 0.5:1; yet even more preferably the ratio is notless than 0.7:1.

According to a preferred embodiment of the present invention, thecorrosion inhibition package is used with an acidic composition such asa modified acid composition comprising:

-   -   a strong acid and an alkanolamine in a molar ratio of not more        than 15:1; preferably in a molar ratio not more than 10:1, more        preferably in a molar ratio of not more than 8:1; even more        preferably in a molar ratio of not more than 5:1; yet even more        preferably in a molar ratio of not more than 3.5:1; and yet even        more preferably in a molar ratio of not more than 2.5:1.

According to a preferred embodiment of the present invention, there isprovided a use of a corrosion inhibitor package with an acidiccomposition where the acidic composition comprises an acid selected fromthe group consisting of: a mineral acid; an organic acid or a syntheticacid, said corrosion inhibitor package comprising:

-   -   a terpene;    -   a cinnamaldehyde or a derivative thereof;    -   at least one amphoteric surfactant; and    -   a solvent.

According to another aspect of the present invention, there is provideda use of a synthetic or modified acid composition comprising a preferredembodiment of the corrosion inhibition package according to the presentinvention in the oil and gas industry to perform an activity selectedfrom the group consisting of: stimulating formations; assisting inreducing breakdown pressures during downhole pumping operations;treating wellbore filter cake post drilling operations; assisting infreeing stuck pipe; descaling pipelines and/or production wells;increasing injectivity of injection wells; lowering the pH of a fluid;fracturing wells; performing matrix stimulations; conducting annular andbullhead squeezes & soaks; pickling tubing, pipe and/or coiled tubing;increasing effective permeability of formations; reducing or removingwellbore damage; cleaning perforations, nozzles, ports, jets, etc.;solubilizing limestone, dolomite, and calcite; and removing undesirablescale, unassisted or natural high formation temperature productionwells, injection wells and their related surface and down-hole equipmentand facilities at temperatures up to 130° C.

According to another aspect of the present invention, there is provideda synthetic or modified acid composition comprising a corrosioninhibition package according to a preferred embodiment for use in theoil and gas industry which has high salinity tolerance. A tolerance forhigh salinity fluids, or brines, can be desirable for offshore acidapplications. Conventional acids are normally blended with fresh waterand additives, typically far offsite, and then transported to the areaof treatment as a finished blend. In certain instances it may proveadvantageous to have an alternative that can be transported as aconcentrate safely to the treatment area, then blended with a salineproduced water or sea water greatly reducing the logistics requirement.A conventional acid composition can precipitate salts/minerals heavilyif blended with fluids of an excessive saline level resulting information plugging or ancillary damage, inhibiting production andsubstantially increasing costs. Brines are also typically present informations, thus having an acidic composition system that has a hightolerance for brines greatly reduces the potential for formation damageor emulsions forming down-hole during or after productplacement/spending (reaction) occurs.

A preferred embodiment of the present invention provides a corrosioninhibition package which provides various oilfield grade steel alloysexceptional protection against corrosion when exposed to acidiccompositions at low to high temperatures (upwards of 130° C.).Additionally, the components used in the preferred corrosion inhibitionpackage are quite environmentally friendly.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The description that follows, and the embodiments described therein, isprovided by way of illustration of an example, or examples, ofparticular embodiments of the principles of the present invention. Theseexamples are provided for the purposes of explanation, and notlimitation, of those principles and of the invention.

According to an aspect of the invention, there is provided a corrosioninhibition package for use with an acidic composition which will beplaced in contact with a metallic surface, said corrosion inhibitionpackage comprising:

-   -   a terpene;    -   cinnamaldehyde or a derivative thereof;    -   at least one amphoteric surfactant; and    -   a solvent.

Preferably, the corrosion inhibition package is used with an acidiccomposition such as a synthetic acid composition comprising:

-   -   lysine & hydrogen chloride in a molar ratio of not less than        1:12; preferably in a molar ratio not less than 1:8, more        preferably in a molar ratio of not less than 1:5, even more        preferably in a molar ratio of not less than 1:3 and even more        preferably in a molar ratio of not less than 1:2.5.

According to another preferred embodiment, the corrosion inhibitionpackage is used with an acidic composition such as a synthetic ormodified acid composition comprising: urea and hydrogen chloride in amolar ratio of not less than 0.1:1; more preferably in the urea andhydrogen chloride are present in a molar ratio of not less than 0.5:1;yet more preferably in the urea and hydrogen chloride are present in amolar ratio of not less than 0.7:1, and even more preferably in the ureaand hydrogen chloride are present in a molar ratio of not less than 1:1.

According to yet another preferred embodiment of the present invention,a corrosion inhibition package comprising a terpene; cinnamaldehyde or aderivative thereof; at least one amphoteric surfactant; and a solvent,can be used with neat HCl. The % volume of the corrosion inhibitionpackage will be determined by the temperature at which the compositionwill be exposed when in use, as well as the type of metal, theconcentration of the HCl and duration of time of exposure. Preferably,the corrosion inhibition package should be present in a concentrationranging from 0.1% to 5 vol % of the volume of the composition.

Preferably, when the synthetic or modified acid composition compriseslysine and hydrogen chloride, the molar ratio of lysine to HCl can rangefrom 1:2 to 1:12; preferably in a molar ratio ranging from 1:2.5 to 1:8,more preferably in a molar ratio ranging from 1:3 to 1:6, even morepreferably in a molar ratio ranging from 1:3 to 1:5.

The terpenes considered by the inventors to achieve desirable corrosioninhibition results comprise: monoterpenes (acyclic); monocyclicterpenes; and beta-Ionone. Exemplary but non-limiting compounds of someof the previously listed terpene sub-classes comprise: for monoterpenes:citral (mixture of geranial and neral); citronellal; geraniol; andocimene; for monocyclic terpenes: alpha-terpinene; carvone; p-cymene.More preferably, the terpenes are selected from the group consisting of:citral; ionone; ocimene; and cymene. Most preferred is citral.

According to a preferred embodiment of the present invention, thecorrosion inhibition package comprises a surfactant which isenvironmentally friendly. More preferably, the surfactant is capable ofwithstanding exposure to temperatures of up to least 130° C. for aperiod of 2 to 6 hours in a closed environment without undergoingdegradation.

Preferably, the at least one amphoteric surfactant is selected from thegroup consisting of: a sultaine surfactant; a betaine surfactant; andcombinations thereof. More preferably, the sultaine surfactant andbetaine surfactant are selected from the group consisting of: an amidobetaine surfactant; an amido sultaine surfactant; and combinationsthereof. Yet even more preferably, the amido betaine surfactant and isselected from the group consisting of: an amido betaine comprising ahydrophobic tail from C8 to C16. Most preferably, the amido betainecomprising a hydrophobic tail from C8 to C16 is cocamidobetaine.

Preferably, the cinnamaldehyde derivative are selected from the groupconsisting of: dicinnamaldehyde p-hydroxycinnamaldehyde;p-methylcinnamaldehyde; p-ethylcinnamaldehyde; p-methoxycinnamaldehyde;p-dimethylaminocinnamaldehyde; p-diethylaminocinnamaldehyde;p-nitrocinnamaldehyde; o-nitrocinnamaldehyde;4-(3-propenal)cinnamaldehyde; p-sodium sulfocinnamaldehydep-trimethylammoniumcinnamaldehyde sulfate;p-trimethylammoniumcinnamaldehyde o-methyl sulfate;p-thiocyanocinnamaldehyde; p-(S-acetyl)thiocinnamaldehyde;p-(S—N,N-dimethylcarbamoylthio)cinnamaldehyde; p-chlorocinnamaldehyde;a-methylcinnamaldehyde; β-methylcinnamaldehyde; a-chlorocinnamaldehydea-bromocinnamaldehyde; a-butyl cinnamaldehyde; a-amylcinnamaldehyde;a-hexylcinnamaldehyde; α-bromo-p-cyanocinnamaldehyde;α-ethyl-p-methylcinnamaldehyde and p-methyl-a-pentylcinnamaldehyde.

Preferably also, the corrosion inhibition package further comprises ananionic surfactant. Preferably, the anionic surfactant is a carboxylicsurfactant. More preferably, the carboxylic surfactant is a dicarboxylicsurfactant. Even more preferably, the dicarboxylic surfactant comprisesa hydrophobic tail ranging from C8 to C16. Most preferably, thedicarboxylic surfactant is sodium lauriminodipropionate

A preferred embodiment can refer to a corrosion inhibition packagecomprising cocamidopropyl betaine and ß-Alanine,N-(2-carboxyethyl)-N-dodecyl-, sodium salt (1:1).

According to a preferred embodiment of the present invention, whenpreparing an acidic composition comprising a corrosion inhibitionpackage, metal iodides or iodates such as potassium iodide, sodiumiodide, cuprous iodide and lithium iodide can be added as corrosioninhibitor intensifier. The iodide or iodate is preferably present in aweight/volume percentage ranging from 0.1 to 1.5%, more preferably from0.25 to 1.25%, yet even more preferably 1% by weight/volume of theacidic composition. Most preferably, the iodide used is potassiumiodide. According to a preferred embodiment, chlorides such as aluminumchloride, calcium chloride, bismuth chloride and magnesium chloride canbe used instead of metal iodides or iodates as intensifiers.

According to a preferred embodiment of the present invention, thecorrosion package comprises: cocamidopropyl betaine in an amount ofapproximately 5% by volume of the total volume of the package; Citral inan amount of approximately 10% by volume of the total volume of thepackage; cinnamaldehyde in an amount of approximately 10% by volume ofthe total volume of the package; and methanol in an amount ofapproximately 75% by volume of the total volume of the package.

Also, preferably, the corrosion inhibition package is used with anacidic composition such as a modified acid composition comprising:

-   -   a strong acid and an alkanolamine in a molar ratio of not more        than 15:1; preferably in a molar ratio not more than 10:1, more        preferably in a molar ratio of not more than 8:1; even more        preferably in a molar ratio of not more than 5:1; yet even more        preferably in a molar ratio of not more than 3.5:1; and yet even        more preferably in a molar ratio of not less than 2.5:1.

In that respect, the composition comprises an alkanolamine and a strongacid, such as HCl, nitric acid, sulfuric acid, sulfonic acid. Thealkanolamine according to the present invention contains at least oneamino group, —NH 2, and one alcohol group, —OH. Preferred alkanolaminesinclude, but are not limited to, monoethanolamine, diethanolamine andtriethanolamine. More preferred are monoethanolamine, diethanolamine.Most preferred is monoethanolamine.

According to a preferred method of use, the corrosion inhibitor packageis mixed with an acid prior to its transport to a job site.Alternatively, a corrosion inhibitor package according to the presentinvention can be mixed with the acid prior to its use while using propermixing equipment and mixing the combined composition thoroughly toensure homogenous mixing.

Example 1—Process to Prepare an Acidic Composition Comprising aCorrosion Inhibition Package According to a Preferred Embodiment of theInvention

The corrosion inhibition package is prepared by dispersing a terpenecomponent in a solvent, in this case methanol, and at least onesurfactant. Afterwards, the corrosion inhibition package thus preparedis mixed with an acidic composition. Applying this procedure, allows forthe formation of a surfactant complex as described below.

According to a preferred embodiment of the present invention, since thecorrosion inhibition package is intended for use at high temperatures,the combination of a betaine and a carboxylic surfactant is desirable.The combination of a carboxylic surfactant and a betaine is known toform a 1:1 or 1:2 complex, which also has a high molecular weight.Therefore, it is important to disperse the terpene component intoisopropanol. Otherwise, the resulting acidic composition may not meetthe class 1 fluid (transparent, no phase separation).

To prepare an aqueous acidic composition of a modified acid, lysinemono-hydrochloride is used as starting reagent. To obtain a 1:2 molarratio of lysine to HCl, 370 ml of 50 wt % lysine-HCl solution and 200 mlHCl aq. 36% (22 Baume) are combined. The corrosion inhibition packageand potassium iodide are added at this point. Circulation is maintaineduntil all products have been solubilized. Additional products can now beadded as required.

The resulting composition of Example 1 is an amber-colored liquid with afermentation-like odour having an expected shelf-life of greater than ayear. It has a freezing point temperature of approximately minus 45° C.and a boiling point temperature of approximately 100° C. It has aspecific gravity of 1.15±0.02. It is completely soluble in water and itspH is less than 1. The composition is biodegradable and is classified asa mild irritant according to the classifications for skin tests. Thecomposition is substantially low fuming. Toxicity testing was calculatedusing surrogate information and the LD₅₀ was determined to be greaterthan 2000 mg/kg.

With respect to the corrosion impact of the acidic composition ontypical oilfield grade steel alloys, it was established that it wasclearly well below the acceptable corrosion limits set by industrymaking it highly desirable as corrosion is the main challenge duringacid applications causing substantial maintenance and workover costsover time.

Corrosion Inhibition Package Formulations

Various types of steel alloy coupons were subjected to corrosion testingin the presence of conventional, synthetic and modified acidcompositions using corrosion inhibitor components according to preferredembodiments of the present invention at various temperatures. Theresults of the corrosion tests are reported in Tables 3 through 31.Coupons of various grades of steel alloys (indicated in each table) wereexposed to the various listed compositions for various periods of timeat varying temperatures. When the fluid system is diluted, it is soindicated in the table or title. For example, 50% indicates that thefluid system was diluted to half strength with tap water. Also, 50%seawater indicates that the fluid system was diluted to half strengthwith seawater (or an equivalent brine solution).

According to preferred embodiment of the present invention, citral canbe present in a concentration ranging from 5 to 30 vol % of the totalvolume of the corrosion inhibition package; cinnamaldehyde can bepresent in a concentration ranging from 5 to 30 vol %; and cocamidobetaine can be present in a concentration ranging from 2.5 to 15 vol %.Depending on various factors, such as temperature, acid, metal, etc.preferred corrosion inhibitor package loadings within the acidcompositions can range between 0.1 to 7.5% vol/vol. More preferably,between 0.1 and 5% vol/vol. Biodegradation, toxicity and bioaccumulationtesting carried out has indicated that most of the compositions listedbelow in Tables 1 and 2 have been identified as satisfactorily meetingthe requirements for listing under a classification of Yellow foroffshore use in the North Sea (Norway).

TABLE 1 List of Component and Content in Corrosion Inhibition PackagesFCI-XV to FCI-XP (All figures are in vol %) FCI- FCI- FCI- FCI- FCI-FCI- FCI- Compound XV XT XS XR XQ XO XP Cocamidopropyl 10 10 10 10 5 510 betaine ß-Alanine, 10 N-(2-carboxyethyl)-N- dodecyl-, sodium salt(1:1) Citral 10 20 25 25 25 25 25 Cinnamaldehyde 25 10 10 10 Carvone 10Methanol 80 70 40 55 60 60 45 Total vol. % 100 100 100 100 100 100 100

TABLE 2 List of Component and Content in Corrosion Inhibition PackagesFCI-XN to FCI-XK (All figures are in vol %) FCI- FCI- FCI- FCI- FCI-FCI- Compound XN XM XL XI XJ XK Cocamidopropyl betaine 10 5 5 10 5 5ß.-Alanine, N-(2- 10 5 10 5 carboxyethyl)-N-dodecyl-, sodium salt (1:1)Citral 10 10 10 15 15 15 Cinnamaldehyde 10 10 10 10 10 10 CarvoneMethanol 60 75 70 55 70 65 Total vol. % 100 100 100 100 100 100

Corrosion Testing

The following corrosion testing outlined in the tables below for anumber of different corrosion inhibition packages according to thepresent invention in the presence of a synthetic or modified acidcomposition was carried out diluted with saline water (in most cases) atvarious temperatures for various durations of exposure. Depending on theintended use/application of an acidic fluid composition comprising acorrosion inhibitor package according to the present invention, adesirable result would be one where the lb/ft² corrosion number is at orbelow 0.05. A more desirable would be one where the corrosion (inlb/ft²) is at or below 0.02. Generally, seawater has the deleteriouseffect of potentiating corrosion, consequently corrosion inhibitionpackages which follow the guidelines or regulations for offshore oilproduction are highly desirable for operators. Where applicable thefluids (acid compositions) were diluted as indicated.

The following abbreviations are used in the corrosion results tables:CI-1A—10% aqueous KI solution; ZA—Cinnamaldehyde; and CA—Citral.

TABLE #3 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 41.4 cm² (coupons used were 1018 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 1.2:1 50%dilution in 1% ZA 0.168 296.053 7.52 0.008 HCl-Urea seawater 1% CI-1A1.2:1 50% dilution in 1% FCI-XT 0.54 954.5765 24.246 0.027 HCl-Ureaseawater 1% CI-1A 1.2:1 50% dilution in 1.5% FCI-XT 0.439 775.107619.688 0.022 HCl-Urea seawater 1% CI-1A 1.2:1 50% dilution in 1% FCI-XS0.18 318.6632 8.094 0.009 HCl-Urea seawater 1% CI-1A 1.2:1 50% dilutionin 1% FCI-XS 0.238 420.7626 10.687 0.012 HCl-Urea seawater 0.5% CI-1A1.2:1 50% dilution in 1.5% FCI-XS 0.151 266.9069 6.779 0.007 HCl-Ureaseawater 1% CI-1A 1.2:1 50% dilution in 1.5% FCI-XS 0.185 327.4953 8.3180.009 HCl-Urea seawater 0.5% CI-1A 1.2:1 50% dilution in 2.5% FCI-XS0.124 218.6835 5.555 0.006 HCl-Urea seawater 1% CI-1A 1.2:1 50% dilutionin 2.5% FCI-XS 0.149 263.904 6.703 0.007 HCl-Urea seawater 0.5% CI-1A1.2:1 50% dilution in 1% FCI-XR 0.235 415.2867 10.548 0.012 HCl-Ureaseawater 1% CI-1A 1.2:1 50% dilution in 1.5% FCI-XR 0.153 270.6164 6.8740.008 HCl-Urea seawater 1% CI-1A 1.2:1 50% dilution in 1% FCI-XQ 0.274484.3539 12.303 0.014 HCl-Urea seawater 1% CI-1A 1.2:1 50% dilution in1% FCI-XQ 0.341 602.5278 15.304 0.017 HCl-Urea seawater 0.5% CI-1A 1.2:1Diluted in 50% 1.5% FCI-XQ 0.18 318.1333 8.081 0.009 HCl-Urea seawater1% CI-1A 1.2:1 Diluted in 50% 1.5% FCI-XQ 0.255 450.0853 11.432 0.013seawater 0.5% CI-1A 1.2:1 Diluted in 50% 1% FCI-XR 0.312 551.3015 14.0030.015 seawater 0.5% CI-1A 1.2:1 Diluted in 50% 1.5% FCI-XR 0.182321.6661 8.17 0.009 seawater 1% CI-1A 1.2:1 Diluted in 50% 1.5% FCI-XR0.213 375.7188 9.543 0.011 HCl-Urea seawater 0.5% CI-1A Where the ratiosare molar ratios and where CI-1A indicates potassium iodide present asintensifier . . .

TABLE #4 Corrosion test results from tests conducted at 110° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 41.4 cm² (coupons used were 1018 steel) Corrosion Wtloss Fluid Package (g) Mils/yr mm/year lb/ft2 21% MSA 1.5% FCI-XQ 0.125220.8032 5.608 0.006 (diluted in 1% CI-1A seawater) 21% MSA 1.5% FCI-XR0.1 176.4659 4.482 0.005 (diluted in 1% CI-1A seawater) 21% MSA 1.5%FCI-XS 0.081 143.6104 3.648 0.004 (diluted in 1% CI-1A seawater) 21% MSA1.5% FCI-XT 1.073 1895.022 48.134 0.053 (diluted in 1% CI-1A seawater)21% MSA 1.5% FCI-XP 0.048 85.49501 2.172 0.002 (diluted in 1% CI-1Aseawater) wherein the 21% MSA solution diluted in seawater is prepare byadding 1 part volume of 42% methanesulfonic acid to 1 part volumeseawater

TABLE #5 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 41.4 cm² (coupons used were 1018 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 1.2:1 50%dilution in 1% FCI-XS 0.171 301.3522 7.654 0.008 HCl-Urea seawater 1%CI-1A 1.2:1 50% dilution in 1% FCI-XS 0.226 399.9188 10.158 0.011HCl-Urea seawater 0.5% CI-1A 1.2:1 50% dilution in 1.5% FCI-XS 0.127224.6894 5.707 0.006 HCl-Urea seawater 1% CI-1A 1.2:1 50% dilution in1.5% FCI-XS 0.147 260.3712 6.613 0.007 HCl-Urea seawater 0.5% CI-1A

TABLE #6 Corrosion test results from tests conducted at 130° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 41.4 cm² (coupons used were 1018 steel) Corrosion Wtloss Fluid Package (g) Mils/yr mm/year lb/ft2 21% MSA 1.5% FCI-XQ 2.2493971.808 100.884 0.111 (diluted in 1% CI-1A seawater) 21% MSA 1.5%FCI-XR 1.763 3114.032 79.096 0.087 (diluted in 1% CI-1A seawater) 21%MSA 1.5% FCI-XS 0.237 418.8195 10.638 0.012 (diluted in 1% CI-1Aseawater) 21% MSA 1.5% FCI-XT 2.849 5032.37 127.822 0.141 (diluted in 1%CI-1A seawater) 21% MSA 1.5% FCI-XP 0.114 201.9025 5.128 0.006 (dilutedin 1% CI-1A seawater)

TABLE #7 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 4 or 6 hours with a coupon density of 7.86 g/cchaving a surface area of 26.01 cm² (coupons used were CR-13-110polished) Corrosion Wt loss Time Fluid Dilution Package (g) (hours)Mils/yr mm/year lb/ft2 HCR-2000N 50% dilution in 5% FCI-XR 0.66 42785.604 70.754 0.044 seawater 5% CI-1A HCR-2000N 50% dilution in 5%FCI-XP 0.459 4 1934.108 49.126 0.03 seawater 5% CI-1A

TABLE #8 Corrosion test results from tests conducted at 70° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 41.4 cm² (coupons used were 1018 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 1.2:1 50%dilution in 1% FCI-XQ 0.076 133.3651 3.387 0.004 HCl-Urea seawater 1%CI-1A 1.2:1 50% dilution in 1% FCI-XQ 0.09 158.2717 4.02 0.004 HCl-Ureaseawater 0.5% CI-1A 1.2:1 50% dilution in 1.5% FCI-XQ 0.076 133.54183.392 0.004 HCl-Urea seawater 1% CI-1A 1.2:1 50% dilution in 1.5% FCI-XQ0.087 153.679 3.903 0.004 HCl-Urea seawater 0.5% CI-1A 1.2:1 50%dilution in 1% FCI-XR 0.081 142.3739 3.616 0.004 HCl-Urea seawater 1%CI-1A 1.2:1 50% dilution in 1% FCI-XR 0.097 171.1667 4.348 0.005HCl-Urea seawater 0.5% CI-1A 1.2:1 50% dilution in 1.5% FCI-XR 0.076133.5418 3.392 0.004 HCl-Urea seawater 1% CI-1A 1.2:1 50% dilution in1.5% FCI-XR 0.091 160.7447 4.083 0.005 HCl-Urea seawater 0.5% CI-1A1.2:1 50% dilution in 1% FCI-XS 0.077 136.0148 3.455 0.004 HCl-Ureaseawater 1% CI-1A 1.2:1 50% dilution in 1% FCI-XS 0.097 170.8134 4.3390.005 HCl-Urea seawater 0.5% CI-1A 1.2:1 50% dilution in 1.5% FCI-XS0.065 114.9943 2.921 0.003 HCl-Urea seawater 1% CI-1A 1.2:1 50% dilutionin 1.5% FCI-XS 0.07 124.0031 3.15 0.003 HCl-Urea seawater 0.5% CI-1A

TABLE #9 Corrosion test results from tests conducted at 110° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 41.4 cm² (coupons used were 1018 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 4.5:1 50%dilution in 1.5% FCI-XQ 0.463 817.5018 20.765 0.023 HCl-Lysine seawater1% CI-1A 4.5:1 50% dilution in 1.5% FCI-XR 0.176 311.4209 7.91 0.009HCl-Lysine seawater 1% CI-1A 4.5:1 50% dilution in 1.5% FCI-XS 0.157276.6223 7.026 0.008 HCl-Lysine seawater 1% CI-1A 4.5:1 50% dilution in1.5% FCI-XP 0.238 421.1159 10.696 0.012 HCl-Lysine seawater 1% CI-1A4.5:1 50% dilution in 1.5% FCI-XT 1.12 1978.927 50.265 0.055 HCl-Lysineseawater 1% CI-1A

TABLE #10 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 28.922 cm² (coupons used were J55 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 observations 7.5%HCl None None 1.404 3550.3032 90.178 0.100 15% HCl None None 2.1755500.3023 139.708 0.154 1.2:1 50% dilution in 1.5% FCI-XP 0.119 300.38897.63 0.008 no pits HCl-Urea seawater 1% CI-1A 1.2:1 50% dilution in 1.5%FCI-XQ 0.218 551.4715 14.007 0.015 no pits HCl-Urea seawater 1% CI-1A1.2:1 50% dilution in 1.5% FCI-XR 0.216 546.6673 13.885 0.015 no pitsHCl-Urea seawater 1% CI-1A 1.2:1 50% dilution in 1.5% FCI-XS 0.186470.8115 11.959 0.013 no pits HCl-Urea seawater 1% CI-1A

TABLE #11 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 30.199 cm² (coupons used were N80 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 observationsHCl-Urea none none 0.117 304.9971 7.747 0.009 (control) HCl-Urea 50%dilution in none 0.370 963.1762 24.465 0.027 seawater 1.2:1 50% dilutionin 1.5% FCI-XP 0.128 310.2075 7.879 0.009 few pits on HCl-Urea seawater1% CI-1A side/back 1.2:1 50% dilution in 1.5% FCI-XQ 0.278 672.479517.081 0.019 no pits HCl-Urea seawater 1% CI-1A 1.2:1 50% dilution in1.5% FCI-XR 0.247 598.3784 15.199 0.017 no pits HCl-Urea seawater 1%CI-1A 1.2:1 50% dilution in 1.5% FCI-XS 0.206 500.0613 12.702 0.014 nopits HCl-Urea seawater 1% CI-1A

TABLE #12 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 30.199 cm² (coupons used were L80 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 observations1.2:1 50% dilution in 1.5% FCI-XP 0.153 369.779 9.392 0.01 few pits onHCl-Urea seawater 1% CI-1A side/back 1.2:1 50% dilution in 1.5% FCI-XQ0.289 698.875 17.751 0.02 no pits HCl-Urea seawater 1% CI-1A 1.2:1 50%dilution in 1.5% FCI-XR 0.296 716.0684 18.188 0.02 no pits HCl-Ureaseawater 1% CI-1A 1.2:1 50% dilution in 1.5% FCI-XS 0.232 562.538714.288 0.016 no pits HCl-Urea seawater 1% CI-1A

TABLE #13 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 28.922 cm² (coupons used were P110 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 observations1.2:1 50% dilution in 1.5% FCI-XP 1.575 3983.187 101.173 0.078 no pitsHCl-Urea seawater 1% CI-1A 1.2:1 50% dilution in 1.5% FCI-XQ 0.6451630.141 41.406 0.046 Yes, some HCl-Urea seawater 1% CI-1A pits on sides1.2:1 50% dilution in 1.5% FCI-XR 0.77 1945.954 49.427 0.055 Yes, someHCl-Urea seawater 1% CI-1A pits on sides 1.2:1 50% dilution in 1.5%FCI-XS 0.387 978.5395 24.855 0.027 no pits HCl-Urea seawater 1% CI-1A

TABLE #14 Corrosion test results from tests conducted at 130° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 28.922 cm² (coupons used were 1018 steel) Corrosion Wtloss Surface Fluid Dilution Package (g) area Mils/yr mm/year lb/ft24.5:1 50% dilution in 1.5% FCI-XQ 1.399 28.922 3537.913 89.863 0.099HCl-Lysine seawater 1% CI-1A 4.5:1 50% dilution in 1.5% FCI-XR 1.11441.4 1966.915 49.96 0.055 HCl-Lysine seawater 1% CI-1A 4.5:1 50%dilution in 1.5% FCI-XS 0.336 41.4 592.8125 15.057 0.017 HCl-Lysineseawater 1% CI-1A 4.5:1 50% dilution in 1.5% FCI-XT 3.839 41.4 6780.955172.236 0.19 HCl-Lysine seawater 1% CI-1A 4.5:1 50% dilution in 1.5%FCI-XP 0.315 41.4 556.4241 14.133 0.016 HCl-Lysine seawater 1% CI-1A

TABLE #15 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 41.4 cm² (coupons used were 1018 steel) Corrosion Wtloss Fluid Package (g) Mils/yr mm/year lb/ft2 15% HCl 1.5% FCI-XP 0.075132.8352 3.374 0.004 1% CI-1A 15% HCl 2.5% FCI-XP 0.068 119.587 3.0380.003 1% CI-1A 15% HCl 1.5% FCI-XQ 1.121 1980.693 50.31 0.055 1% CI-1A15% HCl 2.5% FCI-XQ 0.793 1400.069 35.562 0.039 1% CI-1A 15% HCl 1.5%FCI-XR 0.176 310.8909 7.897 0.009 1% CI-1A 15% HCl 2.5% FCI-XR 0.215380.4881 9.664 0.011 1% CI-1A 15% HCl 1.5% FCI-XS 0.2 353.2851 8.9730.01 1% CI-1A 15% HCl 2.5% FCI-XS 0.228 402.2151 10.216 0.011 1% CI-1A

TABLE #16 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 30.199 cm² (coupons used were L80 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 Observations1.2:1 50% dilution 1.5% FCI-XP 0.18 435.6466 11.065 0.012 few pits onHCl-Urea in seawater 0.5% CI-1A side/back 1.2:1 50% dilution 1.5% FCI-XQ0.305 738.8314 18.766 0.021 no pits HCl-Urea in seawater 0.5% CI-1A1.2:1 50% dilution 1.5% FCI-XR 0.305 738.8314 18.766 0.021 no pitsHCl-Urea in seawater 0.5% CI-1A 1.2:1 50% dilution 1.5% FCI-XS 0.317766.4377 19.468 0.021 no pits HCl-Urea in seawater 0.5% CI-1A

TABLE #17 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 28.922 cm² (coupons used were P110 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 Observations1.2:1 50% dilution 1.5% FCI-XP 0.388 981.3209 24.926 0.026 few pits onHCl-Urea in seawater 0.5% CI-1A side/back 1.2:1 50% dilution 1.5% FCI-XQ0.589 1489.555 37.835 0.042 few pits on HCl-Urea in seawater 0.5% CI-1Aside/back 1.2:1 50% dilution 1.5% FCI-XR 0.662 1674.896 42.542 0.047 fewpits on HCl-Urea in seawater 0.5% CI-1A side/back 1.2:1 50% dilution1.5% FCI-XS 0.376 951.2314 24.161 0.027 few pits on HCl-Urea in seawater0.5% CI-1A side/back

TABLE #18 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 41.4 cm² (coupons used were 1018 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 15% HCl 50%dilution 1% FCI-XP 0.135 239.3507 6.08 0.007 in seawater 1% CI-1A 15%HCl 50% dilution 1% FCI-XP 0.206 364.0603 9.247 0.01 in seawater 0.5%CI-1A 15% HCl 50% dilution 0.75% FCI-XP 0.094 166.7506 4.235 0.005 inseawater 1% CI-1A 15% HCl 50% dilution 0.75% FCI-XP 0.242 427.121710.849 0.012 in seawater 0.5% CI-1A 15% HCl 50% dilution 1% FCI-XQ 1.1732072.901 52.652 0.058 in seawater 0.5% CI-1A 15% HCl 50% dilution 1%FCI-XR 1.204 2126.07 54.002 0.06 in seawater 0.5% CI-1A 15% HCl 50%dilution 0.75% FCI-XQ 1.022 1805.11 45.85 0.051 in seawater 0.5% CI-1A15% HCl 50% dilution 0.75% FCI-XR 0.801 1415.084 35.943 0.04 in seawater0.5% CI-1A

TABLE #19 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 41.4 cm² (coupons used were 4140 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 15% HCl 50%dilution 1% FCI-XQ 2.553 4510.215 114.559 0.126 in seawater 0.5% CI-1A15% HCl 50% dilution 1% FCI-XR 1.502 2653.171 67.391 0.074 in seawater0.5% CI-1A 15% HCl 50% dilution 0.75% FCI-XQ 5.411 9558.483 242.7850.268 in seawater 0.5% CI-1A 15% HCl 50% dilution 0.75% FCI-XR 2.1723837.03 97.461 0.107 in seawater 0.5% CI-1A 15% HCl 50% dilution 1%FCI-XQ 0.95 1677.221 42.601 0.047 in seawater 1% CI-1A 15% HCl 50%dilution 0.75% FCI-XQ 1.836 3242.628 82.363 0.091 in seawater 1% CI-1A15% HCl 50% dilution 1% FCI-XP 0.316 557.6606 14.165 0.016 in seawater1% CI-1A 15% HCl 50% dilution 0.75% FCI-XP 0.874 1543.856 39.214 0.043in seawater 1% CI-1A 15% HCl 50% dilution 1% FCI-XS 0.154 272.3828 6.9190.008 in seawater 1% CI-1A 15% HCl 50% dilution 0.75% FCI-XS 0.196346.0428 8.789 0.01 in seawater 0.75% CI-1A

TABLE #20 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 28.922 cm² (coupons used were J55 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 1.2:1 50%dilution 1.5% FCI-XP 0.135 340.3396 8.645 0.01 HCl-Urea in seawater 0.5%CI-1A 1.2:1 50% dilution 1.5% FCI-XQ 0.296 748.1908 19.004 0.021HCl-Urea in seawater 0.5% CI-1A 1.2:1 50% dilution 1.5% FCI-XR 0.269680.932 17.296 0.019 HCl-Urea in seawater 0.5% CI-1A 1.2:1 50% dilution1.5% FCI-XS 0.252 638.1999 16.21 0.018 HCl-Urea in seawater 0.5% CI-1A

TABLE #21 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 30.199 cm² (coupons used were N80 steel) Corrosion Wtloss Fluid Dilution Package (g) Mils/yr mm/year lb/ft2 1.2:1 50%dilution 1.5% FCI-XP 0.188 455.7459 11.576 0.013 HCl-Urea in seawater0.5% CI-1A 1.2:1 50% dilution 1.5% FCI-XQ 0.331 802.5196 20.384 0.022HCl-Urea in seawater 0.5% CI-1A 1.2:1 50% dilution 1.5% FCI-XR 0.351851.1939 21.62 0.024 HCl-Urea in seawater 0.5% CI-1A 1.2:1 50% dilution1.5% FCI-XS 0.298 721.3959 18.323 0.02 HCl-Urea in seawater 0.5% CI-1A

TABLE #22 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc having asurface area of 30.199 cm² (various steel coupons were used) CorrosionWt loss Surface area Metal Fluid Package (g) (cm²) Mils/yr mm/yearlb/ft2 L80-13CR 1.2:1 2.5% FCI-XP 0.028 8.47 244.3424 6.206 0.007HCl-Urea 5% CI-1A (Diluted in 50% seawater) L80-13CR 1.2:1 5% FCI-XP0.022 8.47 185.6311 4.715 0.005 HCl-Urea 5% CI-1A (Diluted in 50%seawater) L80-13CR 1.2:1 5% FCI-XR 0.019 8.47 161.4559 4.101 0.005HCl-Urea 5% CI-1A (Diluted in 50% seawater) L80-13CR 1.2:1 5% FCI-XQ0.02 8.47 171.8167 4.364 0.005 HCl-Urea 5% CI-1A (Diluted in 50%seawater) L80-13CR 1.2:1 5% FCI-XS 0.015 8.47 127.7833 3.246 0.004*HCl-Urea 5% CI-1A (Diluted in 50% seawater) L80-13CR 1.2:1 5% FCI-XO0.044 8.47 376.4426 9.562 0.011 HCl-Urea 5% CI-1A (Diluted in 50%seawater) J55 1.2:1 1.5% FCI-XM 0.294 28.922 743.8923 18.895 0.021HCl-Urea 1% CI-1A (Diluted in 50% seawater) N80 1.2:1 1.5% FCI-XM 0.36330.199 878.0737 22.303 0.025 HCl-Urea 1% CI-1A (Diluted in 50% seawater)J55 15% HCl 0.75% FCI-XM 0.308 28.922 777.7746 19.755 0.022 0.5% CI-1AN80 15% HCl 0.75% FCI-XM 0.98 30.199 2373.414 60.285 0.066 0.5% CI-1AJ55 1.2:1 1.5% FCI-XL 0.117 28.922 295.079 7.495 0.008 HCl-Urea 1% CI-1A(Diluted in 50% seawater) N80 1.2:1 1.5% FCI-XL 0.156 30.199 377.52819.589 0.011 HCl-Urea 1% CI-1A (Diluted in 50% seawater) N80 15% HCl 1.5%FCI-XM 0.238 30.199 577.3104 14.664 0.016 1% CI-1A *no pits, butcheckered surface

TABLE #23 Corrosion test results from tests conducted at 90° C. for aperiod ranging for 6 hours with a coupon density of 7.86 g/cc SteelCorrosion Wt loss type Fluid Dilution Package (g) Surface area Mils/yrmm/year lb/ft2 1018 1.2:1 50% dilution 1.5% FCI-XM 0.338 41.4 597.581815.179 0.017 HCl-Urea in seawater 1% CI-1A N80 1.2:1 50% dilution 2%FCI-XM 0.196 30.199 475.6031 12.080 0.013 HCl-Urea in seawater 1% CI-1AJ55 1.2:1 50% dilution 2% FCI-XM 0.191 28.922 482.9484 12.267 0.014HCl-Urea in seawater 1% CI-1A L80 1.2:1 50% dilution 2% FCI-XM 0.30530.199 738.8314 18.766 0.021 HCl-Urea in seawater 1% CI-1A N80 1.2:1 50%dilution 1.5% FCI-XL 0.148 30.199 357.9131 9.091 0.010 HCl-Urea inseawater 1% CI-1A J55 1.2:1 50% dilution 1.5% FCI-XL 0.115 28.922290.0219 7.367 0.008 HCl-Urea in seawater 1% CI-1A L80 1.2:1 50%dilution 1.5% FCI-XL 0.115 30.199 278.2423 7.067 0.008 HCl-Urea inseawater 1% CI-1A

TABLE 24 Corrosion testing results carried on various steel coupons(having a surface are of 8.47 cm²) with a metal density of 7.86 g/ccTemp Corrosion Run time Coupon Fluid ° C. Package (hours) Mils/yrMm/year Lb/ft2 Pit Index L80-13CR 90% 4.5:1 90 5% FCI-XM 6 285.78557767.259 0.008 HCl-Lysine 5% CI-1A L80-13CR 90% 4.5:1 90 7.5% FCI-XM 6240.0253492 6.097 0.007 HCl-Lysine 7.5% CI-1A L80-13CR 90% 4.5:1 90 4%FCI-XM 6 297.8731851 7.566 0.008 HCl-Lysine 4% CI-1A L80-13CR 90% 4.5:190 3% FCI-XM 6 282.3319754 7.171 0.008 HCl-Lysine 3% CI-1A 2507 90%4.5:1 90 7.5% FCI-XM 6 898.7999585 22.830 0.025 few blisters HCl-Lysine7.5% CI-1A 2507 90% 4.5:1 90 4% FCI-XM 6 2206.851771 56.054 0.062 manyblisters HCl-Lysine 4% CI-1A 2507 90% 4.5:1 90 7.5% FCI-XM 3 383.34983829.737 0.005 HCl-Lysine 7.5% CI-1A 2507 90% 4.5:1 90 7.5% FCI-XM 4314.7094956 7.994 0.006 HCl-Lysine 7.5% CI-1A 2507 90% 4.5:1 90 7.5%FCI-XM 5 446.5507575 11.342 0.010 HCl-Lysine 7.5% CI-1A 2507 90% 4.5:190 5% FCI-XM-AZ 5 771.8800797 19.606 0.018 many blisters HCl-Lysine 5%CI-1A L80-13CR 50% 4.5:1 90 5% FCI-XM 6 186.4945159 4.737 0.005HCl-Lysine 5% CI-1A L80-13CR 50% 4.5:1 90 7.5% FCI-XM 6 197.71872295.022 0.006 HCl-Lysine 7.5% CI-1A 2507 50% 4.5:1 90 5% FCI-XM 5782.2408861 19.869 0.018 HCl-Lysine 5% CI-1A 2507 50% 4.5:1 90 7.5%FCI-XM 5 662.0555314 16.816 0.015 HCl-Lysine 7.5% CI-1A 2507 50% 4.5:190 7.5% FCI-XM 6 677.7694212 17.215 0.019 HCl-Lysine 7.5% CI-1A 2507 15%HCl 90 5% FCI-XM 6 512.8599187 13.027 0.014 5% CI-1A 2507 15% HCl 907.5% FCI-XM 6 427.3832656 10.856 0.012 7.5% CI-1A 2507 75% 4.5:1 90 5%FCI-XM 5 44166.04569 1121.818 1.033 HCl-Lysine 5% CI-1A 2507 75% 4.5:190 7.5% FCI-XM 5 44124.60246 1120.765 1.032 HCl-Lysine 7.5% CI-1A 250775% 4.5:1 90 7.5% FCI-XM 6 37018.298 940.265 1.039 HCl-Lysine 7.5% CI-1A

TABLE 25 Corrosion testing results carried on 1018 steel coupons with ametal density of 7.86 g/cc (surface area of 41.4 cm²) for a run time of6 hours Temp Corrosion Fluid ° C. Package Mils/yr Mm/year Lb/ft2 PitIndex 15% HCl 110 1.5 FCI-XM 316.1902066 8.031 0.009 1% CI-1A 15% HCl110 2 FCI-XM 351.1654362 8.920 0.010 1% CI-1A 15% HCl 110 2 FCI-XM312.1274274 7.928 0.009 1.5% CI-1A 15% HCl 90 1.5% FCI-XM 2327.97247759.131 0.065 1% CI-1A 15% HCl 70 1% FCI-XM 141.667344 3.598 0.004 0.75%CI-1A 15% HCl 90 1.5% FCI-XM 631.1439153 16.031 0.018 1% CI-1A 15% HCl90 2 FCI-XM 372.7158302 9.467 0.010 1% CI-1A 15% HCl 90 2 FCI-XM322.7259819 8.197 0.009 1.5% CI-1A 15% HCl 115 2 FCI-XM 5645.673293143.400 0.158 1.5% CI-1A

TABLE 26 Corrosion testing results carried using 15% HCl on J55 or L80steel coupons with a metal density of 7.86 g/cc Temp Corrosion Surfacearea Run time Coupon ° C. Package (cm2) (hours) Mils/yr Mm/year Lb/ft2J55 90 1.5 FCI-XM 28.922 6 472.0757814 11.991 0.013 1.0% CI-1A J55 1151.5 FCI-XM 28.922 6 1225.070788 31.117 0.034 1.0% CI-1A J55 115 2 FCI-XM28.922 6 612.6618203 15.562 0.017 1.5% CI-1A L80 115 2 FCI-XM 30.199 24463.2528848 11.767 0.052 1.5% CI-1A

TABLE 27 Corrosion testing results carried on Q-125 steel coupons(having a surface are of 45.71 cm²) for a run time of 6 hours at varioustemperatures Temp Corrosion Fluid ° C. Package Mils/yr Mm/year Lb/ft2Pit Index 90% 4.5:1 90 2.5 FCI-XM 258.0589172 6.555 0.007 No pitsHCl-Lysine 2.0% CI-1A 90% 4.5:1 90 1.75 FCI-XM 257.4189695 6.538 0.007Yes HCl-Lysine 2.0% CI-1A 50% 4.5:1 90 2.5 FCI-XM 368.1299246 9.3510.010 Yes HCl-Lysine 2.0% CI-1A 50% 4.5:1 90 2.75 FCI-XM 333.89272178.481 0.009 Yes HCl-Lysine 2.5% CI-1A 50% 4.5:1 90 1.0 FCI-XM190.8644068 4.848 0.005 Yes HCl-Lysine 1.0% CI-1A 21% MSA 90 1.5 FCI-XM255.8191002 6.498 0.007 No pits 1.0% CI-1A 90% 4.5:1 120 3.0 FCI-XM777.2165032 19.741 0.022 Yes HCl-Lysine 3.0% CI-1A 90% 4.5:1 120 5.0FCI-XM 705.3823719 17.917 0.020 Yes HCl-Lysine 5.0% CI-1A 21% MSA 1202.0 FCI-XM 1058.793499 26.893 0.030 Yes 1.5% CI-1A 21% MSA 120 2.5FCI-XM 457.7226051 11.626 0.013 Yes 2.0% CI-1A 21% MSA 90 2.25 FCI-XM213.7425377 5.429 0.006 No pits 2.0% CI-1A 50% 4.5:1 90 3.5 FCI-XM353.8910879 8.989 0.010 Yes HCl-Lysine 3.5% CI-1A

TABLE 28 Corrosion testing results carried on various steel coupons at atemperature of 90° C. Corrosion Coupon Fluid Package Surface area Runtime Mils/yr Mm/year Lb/ft2 N80 Spent 50% 4.5:1 1.75% FCI-XM 30.199 249.081015776 0.231 0.001 HCl-Lysine 0.75% CI- N80 Spent 90% 4.5:1 1.75%FCI-XM 30.199 24 14.0453044 0.357 0.002 HCl-Lysine 0.75% CI- SuperDuplex Spent 90% 4.5:1 1.75% FCI-XM 33.497 6 1.309908806 0.033 0.0002507 HCl-Lysine 0.75% CI- Super Duplex Spent 90% 4.5:1 1.75% FCI-XM33.497 6 3.274772014 0.083 0.000 2507 HCl-Lysine 0.75% CI-

TABLE 29 Corrosion testing results carried out using 15% HCl on 1018steel coupons (having a surface are of 41.4 cm²) for a run time of 6hours at various temperatures Temp Corrosion ° C. Package Mils/yrMm/year Lb/ft2 120 1.0% FCI-XL 203.3156021 5.164 0.006 1.0% CI-1A 1201.5% FCI-XL 189.8907666 4.823 0.005 1.0% CI-1A 120 2.0% FCI-XL167.9870874 4.267 0.005 1.0% CI-1A 120 1.0% FCI-XL 151.3826855 3.8450.004 1.75% CI-1A 120 1.5% FCI-XL 130.7155044 3.320 0.004 1.75% CI-1A120 2.0% FCI-XL 137.6045648 3.495 0.004 1.75% CI-1A 90 0.5% FCI-XL140.430846 3.567 0.004 0.5% CI-1A 90 1.0% FCI-XL 91.85413824 2.333 0.0030.5% CI-1A 90 1.5% FCI-XL 72.07017 1.831 0.002 0.5% CI-1A 90 0.5% FCI-XL132.4819302 3.365 0.004 0.75% CI-1A 90 1.0% FCI-XL 81.25558383 2.0640.002 0.75% CI-1A 90 1.5% FCI-XL 63.59132647 1.615 0.002 0.75% CI-1A 900.3% FCI-XL 4466.230829 113.442 0.125 0.2% CI-1A 90 0.5% FCI-XL278.2120533 7.067 0.008 0.2% CI-1A 120 1.0% FCI-XL 316.5434918 8.0400.009 0.5% CI-1A 120 1.5% FCI-XL 250.6558119 6.367 0.007 0.75% CI-1A 900.4% FCI-XL 960.0523872 24.385 0.027 0.2% CI-1A 120 0.75% FCI-XL279.4485513 7.098 0.008 0.5% CI-1A 120 1.0% FCI-XL 275.032487 6.9860.008 0.25% CI-1A

TABLE 30 Corrosion testing results carried out using 15% HCl on Q-125steel coupons (having a surface are of 45.71 cm²) for a run time of 6hours at various temperatures Temp Corrosion Surface area Coupon (° C.)Package (cm2) Mils/yr Mm/year Lb/ft2 Pit index L80 90 0.5% FCI-XL 30.199312.8712635 7.947 0.009 2 0.2% CI-1A N80 90 0.5% FCI-XL 30.199202.6882721 5.148 0.006 3 0.2% CI-1A J55 90 0.5% FCI-XL 28.922215.1775522 5.466 0.006 0 0.2% CI-1A P110 90 0.5% FCI-XL 28.922308.2273045 7.829 0.009 0 0.2% CI-1A QT-900 90 0.5% FCI-XL 34.31143.8728277 3.654 0.004 1 0.2% CI-1A 1018CS 90 0.5% FCI-XL 37.712499.530509 12.688 0.014 2 0.2% CI-1A L80 120 1.0% FCI-XL 30.199985.3507518 25.028 0.028 6 0.25% CI-1A N80 120 1.0% FCI-XL 30.199629.3749334 15.986 0.018 7 0.25% CI-1A J55 120 1.0% FCI-XL 28.922356.0164436 9.043 0.010 1 0.25% CI-1A P110 120 1.0% FCI-XL 28.922614.9374935 15.619 0.017 1 0.25% CI-1A QT-900 120 1.0% FCI-XL 34.31600.8555574 15.262 0.017 2 0.25% CI-1A 1018CS 120 1.0% FCI-XL 37.712776.2502436 19.717 0.022 1 0.25% CI-1A N80 80 1.5% FCI-XM 30.199311.418301 7.910 0.009 (w/6-3*) 1.0% CI-1A N80 80 1.5% FCI-XM 30.199501.2720708 12.732 0.014 (w/6-3*) wherein 6-3 refers to a short chainethoxylate present as solvent in the corrosion package. It replacesentirely the initial solvent used in the CI package, i.e. methanol.

TABLE 31 Corrosion testing results carried out using 90% MEA:HCl (in a1:4 ratio) on L80-13CR steel coupons (having a density of 7.86 g/cc andsurface are of 8.47 cm²) for a run time of either 5 or 6 hours atvarious temperatures Temp Corrosion Initial wt. Final wt. Loss wt. ° C.Package (g) (g) (g) Run time Mils/yr mm/year lb/ft2 Pit Index 90 3.0%FCI-XM 4.5062 4.4855 0.021 6 178.7239111 4.540 0.005 3.0% CI-1A 90 5.0%FCI-XM 4.5087 4.4888 0.020 6 171.8167068 4.364 0.005 5.0% CI-1A 110 3.0%FCI-XM 4.4348 4.3916 0.043 6 372.9890318 9.474 0.010 3.0% CI-1A 110 5.0%FCI-XM 4.4964 4.4538 0.043 6 367.8086286 9.342 0.010 5.0% CI-1A 90 2.5%FCI-XM 4.5042 4.4814 0.023 6 196.8553223 5.000 0.006 N 2.0% CI-1A 902.5% FCI-XM 4.4481 4.4267 0.021 6 184.7677148 4.693 0.005 N 2.5% CI-1A110 2.5% FCI-XM 4.4813 4.4334 0.048 6 413.568857 10.505 0.012 N 2.5%CI-1A 110 3.0% FCI-XM 4.4714 4.4397 0.032 6 273.6979701 6.952 0.008 N3.0% CI-1A 110 2.5% FCI-XM 4.5117 4.4957 0.016 5 165.772903 4.211 0.004N 2.5% CI-1A 110 3.0% FCI-XM 4.4393 4.4127 0.027 5 275.5974513 7.0000.006 N 3.0% CI-1A

Additionally, corrosion inhibition packages according to preferredembodiments of the present invention will allow the end user to utilizesynthetic and modified acids that have down-hole performance advantages,transportation and storage advantages as well as the health, safety andenvironmental advantages. The person skilled in the art will alsounderstand that the corrosion package according to the present inventionis also useful when utilized with conventional acid systems.

In addition to stability at high temperatures and desirable corrosionrates as discussed above, the use of synthetic and modified acids alongwith a corrosion package according to a preferred embodiment of thepresent invention, allows for at least one of the following advantages:reduction in skin corrosiveness, a more controlled or methodicalspending or reacting property, minimizing near well bore damagetypically caused by an ultra-aggressive reaction with the formationtypically caused by HCl and increasing formation penetration providingsuperior production over time.

Uses of Corrosion Inhibition Packages According to Preferred Embodimentsof the Present Invention

The uses (or applications) of the corrosion inhibition packagesaccording to the present invention when combined (or mixed) with acidiccompositions upon dilution of the latter ranging from approximately 1 to90% dilution, include, but are not limited to: injection/disposal welltreatments; matrix acid squeezes, soaks or bullheads; acid fracturing,acid washes; fracturing spearheads (breakdowns); pipeline scaletreatments, cement breakdowns or perforation cleaning; pH control; andde-scaling applications. As would be understood by the person skilled inthe art, the methods of use generally comprise the following steps:providing a composition comprising a corrosion inhibitor packageaccording to a preferred embodiment of the present; mixing said packagewith an acid composition; exposing a surface (such as a metal surface)to the acid composition comprising the package; allowing the acidcomposition a sufficient period of time to act upon said surface; andoptionally, removing the acid composition when the exposure time hasbeen determined to be sufficient for the operation to be complete orsufficiently complete. Another method of use comprises: injecting theacid composition comprising the package into a well and allowingsufficient time for the acid composition to perform its desiredfunction. Yet another method of use comprises: exposing the acidcomposition comprising the package to a body of fluid (typically water)requiring a decrease in the pH and allowing sufficient exposure time forthe acid composition to lower the pH to the desired level.

One of the advantages of the use of a synthetic acid composition using acorrosion inhibition package according to a preferred embodiment of thepresent invention includes: the reduction of the total loads of acid,and the required number of tanks by delivering concentrated product tolocation and diluting with fluids available on location (with low tohigh salinity production water).

While the foregoing invention has been described in some detail forpurposes of clarity and understanding, it will be appreciated by thoseskilled in the relevant arts, once they have been made familiar withthis disclosure that various changes in form and detail can be madewithout departing from the true scope of the invention in the appendedclaims.

1. A corrosion inhibition package for use with an aqueous acidcomposition, said package comprising: a terpene; a cinnamaldehyde or aderivative thereof; at least one amphoteric surfactant; and a solvent.2. The corrosion inhibition package as claimed in claim 1, wherein theterpene is selected from the group consisting of: citral; carvone;ionone; ocimene; cymene; and combinations thereof.
 3. The corrosioninhibition package as claimed in claim 1, wherein the at least oneamphoteric surfactant is selected from the group consisting of: asultaine surfactant; a betaine surfactant; and combinations thereof. 4.The corrosion inhibition package as claimed in claim 1, wherein the atleast one amphoteric surfactant is selected from the group consistingof: an amido betaine surfactant; an amido sultaine surfactant; andcombinations thereof.
 5. The corrosion inhibition package as claimed inclaim 1, wherein the amphoteric surfactant is an amido betainesurfactant and is selected from the group consisting of: an amidobetaine comprising a hydrophobic tail from C8 to C16.
 6. (canceled) 7.The corrosion inhibition package as claimed in claim 1, furthercomprising an anionic surfactant.
 8. (canceled)
 9. The corrosioninhibition package as claimed in claim 1, further comprising acarboxylic surfactant which is a dicarboxylic surfactant.
 10. (canceled)11. The corrosion inhibition package as claimed in claim 1, furthercomprising sodium lauriminodipropionate.
 12. The corrosion inhibitionpackage as claimed in claim 1, wherein the amphoteric surfactant isselected from the group consisting of: cocamidopropyl betaine;ß-Alanine, N-(2-carboxyethyl)-N-dodecyl-, sodium salt (1:1); and acombination thereof.
 13. The corrosion inhibition package as claimed inclaim 1, wherein the solvent is selected from the group consisting of:isopropanol; methanol; ethanol; 2-butoxyethanol; diethylene glycol; ashort chain ethoxylate; and combinations thereof.
 14. The corrosioninhibition package as claimed in claim 1, wherein the terpene is presentin an amount ranging from 5% to 30% by volume of the total volume of thecorrosion inhibition package.
 15. The corrosion inhibition package asclaimed in claim 1, wherein the cinnamaldehyde or derivative thereof ispresent in an amount ranging from 5% to 30% by volume of the totalvolume of the corrosion inhibition package.
 16. The corrosion inhibitionpackage as claimed in claim 1, wherein the at least one surfactant ispresent in an amount ranging from 2% to 20% by volume of the totalvolume of the corrosion inhibition package.
 17. The corrosion inhibitionpackage as claimed in claim 1, wherein the solvent is present in anamount ranging from 25% to 80% by volume of the total volume of thecorrosion inhibition package. 18-19. (canceled)
 20. The aqueous acidiccomposition according to claim 1, further comprising a metal iodide oriodate. 21-31. (canceled)
 32. A use of a corrosion inhibitor packagewith an acidic composition where the acidic composition comprises anacid selected from the group consisting of: a mineral acid; an organicacid; a modified acid; a complexed acid or a synthetic acid, saidcorrosion inhibitor package comprising: a terpene; a cinnamaldehyde or aderivative thereof; at least one amphoteric surfactant; and a solvent.33-35. (canceled)
 36. A method of using an aqueous acidic composition inthe oil industry, wherein said method comprising the steps of: preparinga corrosion inhibiting package comprising: a terpene; a cinnamaldehydeor a derivative thereof; at least one amphoteric surfactant; and asolvent; providing an aqueous acid solution; mixing the package into theaqueous acidic solution; applying the resulting composition to a metalsurface; allowing the acid composition a sufficient period of time toact upon said surface; and optionally, removing the acid compositionwhen the exposure time has been determined to be sufficient for theoperation to be complete or sufficiently complete. 37-38. (canceled) 39.The method according to claim 36 to perform an activity in the oilindustry where the activity is selected from the group consisting of:stimulating formations; assisting in reducing breakdown pressures duringdownhole pumping operations; treating wellbore filter cake post drillingoperations; assisting in freeing stuck pipe; descaling pipelines and/orproduction wells; increasing injectivity of injection wells; loweringthe pH of a fluid; fracturing wells; performing matrix stimulations;conducting annular and bullhead squeezes & soaks; pickling tubing, pipeand/or coiled tubing; increasing effective permeability of formations;reducing or removing wellbore damage; cleaning perforations;solubilizing limestone, dolomite, and calcite; and scale removal from asurface selected from the group consisting of: equipment, wells andrelated equipment and facilities.